CARMEL, Ind. — MISO and SPP said Thursday during their annual issues review that they plan to treat Joint Targeted Interconnection Queue (JTIQ) projects as large generator interconnection projects when allocating costs.
The RTOs have proposed allocating 90% of the portfolio’s costs to interconnecting generators and the remaining 10% to their load. SPP’s load will be responsible for 71% of costs, and MISO will shoulder the remaining 29%.
The JTIQ study completed early last year resulted in five projects on the RTOs’ seam that should help reduce congestion and allow additional resources, primarily wind farms, to interconnect with their systems. The portfolio has an estimated cost of $1.06 billion. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
Sumit Brar, reliability analysis lead for MISO long-range planning, said the grid operators will not begin additional JTIQ studies unless the first portfolio has secured enough generation to cover most or more of its costs. Future studies will be conducted on a five-year horizon.
MISO expects the first JTIQ portfolio to support up to 28 GW of interconnecting generation on both sides of the seam.
MISO stakeholders expressed worry that the necessary amount of generation may drop out of the two IC queues, leaving load to handle the bag of costs. Some have also said a 90% cost assignment to interconnecting generation might not be fair.
They asked whether the RTOs might consider adding a cost cap on the per-megawatt charge or enact protections when generation requests drop out of the queue.
“Now, there will be dropouts, so we expect that,” MISO Director of Resource Utilization Andy Witmeier said, adding that the RTO expects it will take “a few queue cycles” to get the lines nearly funded.
Witmeier said it’s “unrealistic” to assume that the grid operators won’t have enough willing generation developers to fully fund the projects.
“Eventually, enough generators will sign up, sign [generator interconnection agreements] in the region,” he said.
The RTOs are proposing that generation be on the hook for a JTIQ per-megawatt cost when a project has a greater than 5% distribution factor on one or more facilities in the affected system and a greater than 1-MW impact on “at least one” JTIQ line.
Steelhead Americas’ Adam Solomon said the threshold was “ridiculously low” when compared to the large interconnection projects in the MISO queue.
MISO and SPP said they don’t plan an interregional planning study this year, saying their plates are full memorializing the targeted market efficiency projects (TMEPs) work and preparing for an expected FERC notice of proposed rulemaking on interregional transfer capability. MISO said its planners are also working on the second tranche of its long-range transmission plan.
The grid operators are required to undertake a coordinated system plan every other year. Last year, the two performed a TMEPs study that failed to identify any small interregional projects. (See MISO, SPP Unable to Find Smaller Joint Tx Projects.)
Basin Electric Power Cooperative had asked the RTOs to study constraints in the Dakotas, and Ameren has requested an examination of chronically congested 161-kV lines and a transformer linked to a 345-kV line in Missouri.
DOE Funding for JTIQs Won’t Affect Cost Allocation
MISO said Tuesday that potential Department of Energy funds will not affect a planned cost-sharing plan for the JTIQ projects.
The program requires that states affected by a project make the application process. Great Plains is organizing stakeholders and coordinating the multistage GRIP application process.
Brar said states with a JTIQ project are all involved. Funding will be granted to states based on the percentage of projects located within their boundaries.
The organizations sent a concept letter to the DOE earlier in January. The DOE will inform applicants by Feb. 24 whether their projects are sufficient enough for a full application that would be due May 19. Approved GRIP projects could potentially be awarded a 50% project match. (See SPP MOPC Briefs: Jan. 17-18, 2023.)
Grid modernization (GM) investments encompass myriad technologies that digitize a utility’s distribution system. They have the potential to improve the reliability of the electrical grid, better integrate alternative energy, and enable pricing that reflects the marginal cost of generation.
The present grid was designed when power plants in central locations exclusively controlled a one-way flow of electricity to customers. A modern grid has the ability to accommodate greater consumer control and two-way flows of power.
Experience has shown that achieving public-policy goals at bearable cost to society frequently requires technological breakthroughs. Many experts assert that making the transition to a clean-energy future at an affordable or politically acceptable cost will demand new technologies, such as those rooted in GM.
It seems then that it is a slam dunk for state regulators to approve utilities’ plans to modernize their distribution systems, even if the cost is high. But, to no surprise, things are rarely as certain as they seem. Public utility commissions face a formidable challenge in ensuring that utility investments in GM advance the nebulous public interest or are cost-beneficial.
Pressure for GM comes from different quarters: electric utilities, Wall Street, clean air and climate advocates, GM technology vendors, consultants, labor unions, and state and federal politicians and bureaucrats. Utility managers themselves favor GM mainly because it will accommodate additional demands from electric vehicles and households for electric space and water heating (i.e., electrification).
Proponents of GM vastly outnumber both skeptics and opponents, making it challenging for regulators to reject GM plans proposed by utilities. We know that strong pressure from special interest groups with political clout can persuade policymakers to decide in their favor, even though it would be detrimental to society overall.
Since utility customers are the eventual payers of GM investments, the critical questions that PUCs need to ask themselves, are whether (1) the total benefits from GM to utility customers exceed the costs and (2) low-income households will overpay given that higher-income households will disproportionally benefit from purchases of electric vehicles and rooftop solar systems that GM tries to accommodate. Just because a Tesla is technologically superior to conventional vehicles does not mean that it is the right choice for everyone. It’s costly, and some car drivers might consider the technological benefits to be nominal.
I have seen too often where utility customers pay through their rates for utility investments directed at benefitting a special interest with political influence; that is, customers funding the advancement of political objectives through inflated rates without compensatory benefits. I ask whether we are seeing a repeat of this for GM investments. Or as one industry observer expressed to me, “Is grid modernization another way to line utility pockets and promote renewable energy and kill fossil fuels?” While this opinion seems extreme, it may not be so far-fetched.
There is great uncertainty over the benefits and costs of GM investments. Costs overruns are common, and benefits are difficult to quantify and require different methods of varying complexity.
A serious problem is a utility’s capital bias combined with laxed regulatory cost controls. Under traditional regulation, utilities collect capital costs only after the regulator considers them prudent or reasonable; utilities would be allowed to collect them only after a general rate case.
But for various reasons, regulators have accepted new cost-recovery approaches. Both utilities and climate activists have pushed for quicker and more certain capital-cost recovery when it comes to certain technologies like GM that advance their agenda. Wall Street has also supported these new approaches, fashioning an Iron Triangle that makes it difficult for PUCs to reject them.
Utilities should be held accountable for subpar performance from GM investments. These investments have often fallen short of achieving the benefits promised in utilities’ plans.
There is evidence that reliability has not improved in states that have so far invested the most in GM. Critics have also questioned whether it is too soon to replace the current infrastructure.
Advanced metering infrastructure (AMI) has in some jurisdictions failed to realize expected dispatch efficiencies and cost savings. Most utilities have also under-exploited the ability of AMI to enable granular time-of-use rates (e.g., real-time pricing, electric vehicle charging rates) that can produce large efficiency gains.
Another problem recognized by PUCs is utilities proposing to make large-scale, multitechnology investments, some of which have questionable, ill-defined benefits that are unlikely to transpire for several years.
PUCs should not outright reject a GM plan just because it would require an increase in electricity rates or be prejudiced against a plan in spite of the evidence; or accept a plan just because it will support a popular clean energy agenda, while ignoring the effect on utility customers. There is danger that either of these scenarios can happen and probably has already in some states.
The experiences across states have shown that the benefits from GM plans are often overstated and costs understated. The burden falls on PUCs to ensure that this does not happen. Unaccountability by utilities for their large investments can have a devastating effect on customers and society as a whole. Getting the incentives right is the key element for achieving socially desirable GM investments.
Kenneth W. Costello is a regulatory economist and independent consultant. He previously worked for the National Regulatory Research Institute, the Illinois Commerce Commission, Argonne National Laboratory and Commonwealth Edison Co.
The Inflation Reduction Act’s electric vehicle tax credits sparked a spirited debate on the Senate floor Thursday as Sen. Debbie Stabenow (D-Mich.) resisted Sen. Joe Manchin’s (D-W.Va.) call for swift passage of a bill that could put a hold on the credits for some EV buyers.
Manchin’s American Vehicle Security Act would force the Internal Revenue Service to put the IRA’s domestic content provisions into effect retroactively, as of Jan. 1. The IRA required the agency to issue guidelines for the tax credit by Dec. 31, but the IRS only issued partial guidelines, delaying action on the domestic content provisions until March and triggering Manchin’s efforts to force the agency’s hand. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)
In the interim, the IRS has said EV buyers can qualify for the full $7,500 tax credit offered in the IRA, without complying with domestic content rules. If Manchin’s bill were to become law, some of those cars might no longer qualify.
Sen. Debbie Stabenow (D-Mich.) | C-SPAN
“Why the IRS did not do their job, I can’t tell you, unless their intent was never trying to comply with what we passed,” Manchin said, moving for his bill to skip a hearing in the Senate Finance Committee and go straight to a floor vote.
Framing the IRA as an “energy security manufacturing” law, Manchin said the domestic content provisions are intended to spur the buildout of a U.S. supply chain for EVs, countering China’s dominance in the EV global market.
“We’re moving rapidly into the EV markets — and I think, recklessly — as we were going into that before we were able to supply [domestic production] and be held captive by China,” he said. The U.S.’s main economic competitor now controls 80% of the world’s battery materials processing and 75% of lithium-ion battery production, he said.
Stabenow had no argument with Manchin on building out a domestic EV supply chain and cutting U.S. dependence on China. But she said the EV tax credit in the IRA “is confusing. It was not well vetted. It is not supported by anyone in the auto industry.”
Objecting to Manchin’s motion for a quick vote on the bill, Stabenow said, “This does not create any path for success for American automobile workers, for American automobile companies, for suppliers, for consumers who are interested in being able to purchase electric vehicles and benefit from a credit.”
She also defended the IRS decision to delay rules on the domestic content provisions as “not unreasonable. … They have been given, I believe, an incredibly complicated task to try to figure out how this consumer credit will work for consumers and for companies and workers,” she said.
The domestic content requirements simply don’t work “on a practical level,” she said.
The Senate recessed without acting on Manchin’s motion.
GOP Support Uncertain
Facing opposition from his fellow Democrats, the bill’s prospects for passage are slim. But Manchin is seeking GOP support, enlisting Rep. Mike Braun (R-Ind.) as a co-sponsor.
Backing up Manchin on Thursday, Braun said he had not supported the IRA. But he said the new bill “is not just about promoting our own manufacturing, which we need to do better generally. It’s also about not funding the human rights abuses of the Chinese Communist Party.”
Sen. Mike Braun (R-Ind.) | C-SPAN
Indiana snagged a major EV battery manufacturing project in May, when Stellantis and Samsung announced plans to invest $2.5 billion in a plant in Kokomo. Delaying the domestic content provisions “sends a bad message to people in our own country about making the investments, and clearly in my own state, there’s a vested interest,” Braun said.
Whether other Republicans will sign on is less certain. Industry analysts ClearView Energy Partners said that even if some Republicans agree with Manchin’s focus on domestic manufacturing, they may be reluctant to sign on because the IRA also links some of its tax credits to “labor-friendly” provisions on prevailing wages and apprenticeships.
“Accordingly, we think Republicans may be leery of backing Manchin’s modification because it could be viewed as a tacit endorsement of the IRA,” ClearView said in an email note on Wednesday.
Opposition from the auto industry is almost certain, with many automakers already concerned about consumer and dealer confusion about the EV tax credit, according to John Bozzella, president of the Alliance for Automotive Innovation, an industry trade group.
“We want to make sure we don’t increase confusion for customers who might be confused already about what qualifies for a tax credit,” Bozzella said. “So I’m not quite sure what the value of the new legislation is.”
Placating Europe
The IRA’s $7,500 EV tax credit is broken down into two parts. Consumers purchasing a new EV may qualify for half the credit if the car’s battery components are at least 50% manufactured and assembled in the U.S. To qualify for the other half, 40% of the critical minerals in the battery, such as lithium or cobalt, must be sourced either in the U.S. or a country with which the U.S. has a free trade agreement.
The law also limits eligibility for the credit based on an EV manufacturer’s suggested retail price (MSRP) and a buyer’s annual income. The MSRP for EV sedans is capped at $55,000 and for SUVs, at $80,000. The income cap for individuals is $150,000 per year and for couples, $300,000 per year.
Beyond causing confusion at home, the EV tax credits and the IRS delayed guidelines on domestic content have also riled European automakers and their governments, who see the incentives as drawing vital investment dollars away from their countries. Despite being one of the U.S.’s major trading partners, the EU does not have a fair-trade agreement with the U.S., meaning its EVs would not quality for the tax credits.
Speaking at the Washington, D.C., Auto Show on Jan. 19, EU Ambassador Stavros Lambrinidis warned that the IRA could set off a “subsidy war” as both the U.S. and EU put billions into transportation decarbonization. (See Tracking the Contradictions of the US EV Market at the DC Auto Show.)
“That’s a danger because the IRA, the way it’s structured, in a sense is endangering investment in Europe. It is sucking away investment potential, especially at a time of very high energy prices,” Lambrinidis said. “Nothing could be worse for the strength of the U.S. economy and U.S. companies than a weak European economy.”
While still working on the domestic content guidelines, the IRS has an online list of EVs and plug-in hybrids it says are qualified for a $7,500 tax credit. Popular U.S. brands — including Ford’s F-150 Lightning, Chevy Bolt and Tesla’s Model 3 and Model Y — are on the list.
The IRS says many foreign automakers have “entered into a written agreement with us to become a ‘qualified manufacturer’ but [haven’t] yet submitted a list of specific makes and models that are eligible.”
The agency may have provided an opening for foreign models that are leased by individuals. In a recent fact sheet, the IRS identifies leased vehicles as eligible for the commercial EV tax credit, which is not subject to the domestic content requirements of the IRA.
The situation has been difficult for the White House, trying to move ahead with IRA implementation while also trying not to alienate the EU, where Manchin’s bill could be seen as adding more fuel to the fire.
But, in a now-divided Congress, Manchin does not have the leverage he had when Democrats controlled both houses and he was a key swing vote in the Senate.
“In the context of a divided Congress, however, the status quo puts [the IRS] in the driver’s seat,” ClearView said. “Not only does the administration have less to lose by overtly countering the Manchin bill, but the White House might be able to placate allies simply by staying silent and letting partisan divisions quash the measure.”
The window closed Thursday afternoon on New York state’s third offshore wind solicitation.
The New York State Energy Research and Development Authority, which is leading the state’s ambitious offshore buildout, did not release details on the submissions. But at least some of the would-be developers are known: Four familiar names announced later Thursday that they had submitted bids.
Equinor and BP, already partners on Beacon Wind 1 and Empire Wind 1 and 2 off the New York coast, submitted a proposal for a 1,360-MW installation in the Beacon Wind 2 lease area.
Ørsted and Eversource, already partners on South Fork Wind and Sunrise Wind, submitted multiple bids with different configurations.
NYSERDA late Thursday said it has begun the bid review and qualifying process and will post a summary as soon as it can. The timeline estimates that companies chosen for contracts will be notified later in the first quarter of this year and the contracts executed in the second quarter.
In a news release Thursday, Equinor (NYSE:EQNR) and BP (NYSE:BP) said their plan would complement the 3.3-GW combined output of the three other wind farms the two partners are developing off the New York coast, and help the state realize its goal of 70% renewable energy by 2030.
They propose to create manufacturing facilities for key components such as cable parts, blades and nacelles in New York. They also promise $50 million for a collaborative effort to train and support workers for the offshore wind industry, with attention to historically marginalized communities and opportunities for minority- and women-owned business enterprises (MWBEs). They included options to install energy storage to help the state with its energy transition and for BP subsidiary BP Pulse to install up to 1,000 ultrafast EV charge points statewide.
In their news release, Ørsted and Eversource (NYSE:ES) provided few details about the multiple configurations they offered in their multiple bids. But they painted a general summary of the expected results: billions of dollars in economic activity for the state’s economy, strides for economic justice, prioritization of disadvantaged communities and MWBEs, and furtherance of the state’s climate goals.
The partners have reported steady progress so far on labor agreements, workforce training and supply chain development. Construction of their 130-MW South Fork Wind has begun, and it is expected to start producing power later this year. Their 924-MW Sunrise Wind is in advanced development with a late 2025 target for operation.
Meanwhile, Rise Light & Power, which owns New York City’s largest fossil fuel-burning power plant, said Wednesday it had secured a stake in an offshore wind project, and said its plans to convert the plant to a clean energy hub would be part of an offshore wind proposal submitted Thursday.
It had not followed up with further public information by late Thursday.
The subsidiary of LS Power last year proposed making its Ravenswood Generating Station the point of interconnection for power generated offshore, a connection to land-based clean-energy sources upstate, a source of clean thermal energy by repurposing its water intakes and a large-scale battery storage site.
It will cost the U.S. up to $100 billion to build and power the charging network necessary for a massive conversion of the nation’s transportation system to electric vehicles, an analyst said this week during a webinar produced by the EV Charging Initiative, a national collaborative.
“We really have to think in terms of how we build this new network. It’s not just a matter of modifying the existing network” of gas and diesel stations, said Phil Angelides, a partner with EVC Partners, a company created to identify viable building sites for EV charging stations in California.
Clockwise from top left: Phil Angelides, Riverview Capital Investments; Patricio Portillo, NRDC; Rachel Zook, Nuvve; and José Miguel Acosta Córdova, Little Village Environmental Justice | The National EV Charging Initiative
The company surveyed existing truck stops throughout California and found that limits on both the distribution and transmission system would make it difficult for many existing truck stops to convert to full EV charging, Angelides, a former California state treasurer, said during a virtual summit of the collaborative focused on Midwestern states.
Electrifying the nation’s transportation sector is a major goal of the Biden administration, which wants 500,000 public charging stations built nationwide by 2030. That’s about half the number that will be needed by then, according to experts outside of the administration, especially if half of all new automobiles sold in 2030 are electric, as administration officials hope, and if trucking companies embrace battery electric drive systems over diesel.
As a point of comparison, there are about 140,000 conventional fueling sites operating in the U.S., said Tom Kloza, global head of energy analysis at Oil Price Information Service. That total does not include the number of fuel pumps at each station, he said.
The Infrastructure Investment and Jobs Act (IIJA), passed in November 2021, created the National Electric Vehicle Infrastructure (NEVI) formula program, administered by the Federal Highway Administration. (See US Completes Review of State EV Charging Plans.)
The legislation provided $5 billion in NEVI formula grants distributed to all 50 states to “strategically deploy” EV charging stations along 75,000 miles of federally designated highway. The law also authorized $2.5 billion for a competitive grant program. Both grants require 20% local matching.
Charger Challenges
In three separate discussions, the conference also looked at what it will take to electrify diesel-powered trucks and buses as quickly as possible and the difficulty involved in planning, building and getting power to public charging stations.
“There has been a significant commitment by the federal government, and a number of states have put resources forward to support the charging infrastructure,” Angelides said. “The money is substantial, but I don’t think it’s sufficient for the issue in front us.
“Given the uncertainty of the timing of when these EVs are going to show up, both in the light-duty passenger space and the medium and heavy-duty truck space, it’s very hard to finance major infrastructure investments against that kind of uncertain revenue.”
Angelides also argued for an immediate review of how utilities, working with state PUCs, plan system upgrades, which typically take three to five years of planning and negotiation.
In a separate panel, Drew Bennett, executive vice president at Volta Charging (NYSE: VLTA), said the availability of power at any potential charging site can determine whether charging stations are built. The availability of labor in a region is also a factor, as is the availability of transformers.
“Transformers are really backordered,” he said, “and taking over a year [to obtain] for some utilities. This is something that I think is not going away. I think if you want DC fast charging or even large Level 2 charging, we’re going to need a lot more transformers put into parking lots in the future, and that’s something that needs to adjust.”
In a third panel, Chris Bast, a climate and decarbonization policy expert and principal at Hua Nani Partners in Virginia, noted that $7.5 billion authorized by the IIJA should be seen as “a down payment” on the administration’s 500,000 charging station goal.
Lynda Tran, director of public engagement at the U.S Department of Transportation, said the federal money is an effort to stimulate broader direct investment from private companies.
“We are creating a market; we’re creating a demand that is now translating into lots of private sector investment,” Tran said, referencing a recent analysis commissioned by the Natural Resources Defense Council that found the EV industry has spent $210 billion since Biden took office.
Light, Heat … and Transportation
The analysis also concludes that the total potential funding, including grants, loans and tax credits, authorized by the IIJA and the Inflation Reduction Act in the coming years amounts to $245 billion. Bast pointed out another even more significant and obvious — but hardly discussed — consequence of the effort to electrify transportation is the merger of the transportation industry and the electric generation and distribution industries.
“It’s becoming clear that one of the big challenges we’ll be addressing over the next decade is the merger of two huge sectors of the economy, transportation and electric,” Bast said.
“And [by electric], I mean electric utilities and their regulators are going to have a big and important role to play as we try and bring these two sectors together.”
Katherine Peretick, a member of the Michigan Public Service Commission, said the issue is difficult because “it requires a totally new way of thinking about the electric sector and electric utilities.”
Clockwise from top left: Chris Best, Hua Nani Partners; Michigan Public Service Commissioner Katherine Peretick; Geoff Gibson, Forth; Lynda Tran, U.S. Department of Transportation; and Brittney Kohler, National League of Cities | The National EV Charging Initiative
Utilities have for decades supplied power for light, heating and cooling, she said, adding that many utilities across the country include the word “light” in the company name.
“Now we are adding transportation to that list. That means that the jobs of utilities and the jobs of regulators are front and center and are more important than ever as a part of this transition. It will require some unprecedented coordination among all of these parties,” Peretick said.
Referencing a recent report from the Electric Vehicle Council of the Fuels Institute, she said most cities and counties surveyed “had little to no public policies for public EV charging.”
“These policies are currently being established, and we need to make sure we are being thoughtful about their implications and purposefully coordinating with a very wide range of stakeholders that are involved in transfers, transportation and electrification planning,” she said.
“We need to intentionally include a wide variety of parties in this conversation, including parties who have not traditionally been included.
“As the usage of the electric grid changes, the way that we pay to maintain and upgrade that grid is also going to need to evolve,” Peretick said.
To illustrate that point, Peretick mentioned a program the state is coordinating with Consumers Energy (NYSE: CMS-PB), a Michigan utility, transmission company ITC Holdings and EV maker Rivian Automotive (NASDAQ: RIVIN) to install EV charging stations in Michigan state parks.
Rivian is installing the chargers; ITC is paying for the power; and Consumers Energy is paying for the upgrades to power lines inside the parks.
The demonstration project is part of a longer-term plan created by Michigan, Illinois and Wisconsin to build and maintain charging stations around the perimeter of Lake Michigan, she said.
Christopher Budzynski, director of utility policy at Exelon (NASDAQ: EXC) — which serves four major metropolitan areas, primarily in the Mid-Atlantic region as well as northern Illinois — said the company is expecting 4 million EVs in its service area between 2025 and 2040, including 1 million in Illinois alone.
Clockwise from top left: Chris Budzynski, Exelon; Nancy Ryan, eMobility Advisors; Drew Bennett, Volta Charging; and Cory Bullis, Flo EV Charging | The National EV Charging Initiative
“I think we need aggressive policies that promote transportation electrification. That’s the starting point. And then I think specifically as it relates to what we can do as a utility is really promoting policies that support programs that allow us to get ahead of this. I think that’s where we’re starting to find some challenges across the industry where things are just happening so quickly,” he said.
“Your traditional utility model says build it and they will come. I think they’re already here. So, we need to start building out a little bit more to get ahead of them coming in. I think as we look at the light-duty vehicles coming on to the system, it’s happening, and it’s happening in a significant way. I think it’s happening quickly,” he continued.
Budzynski thinks Exelon is going to play a “critical role” in building that infrastructure and “supporting our customers and communities.” He said the company has a number of different programs across its utility subsidiaries that will allow for construction of over 7,000 charging ports, serving light-duty vehicles, commercial medium- and heavy-duty fleets and multi-unit dwellings.”
“We’ve got to also think about resilience and reliability and ensuring that we have that along with … wires that support these charging stations. It is a very comprehensive support role that the utility needs to play,” he said.
Cory Bullis, public affairs director for FLO EV Charging, a Canada-based company that manufactures chargers in Michigan, underscored Budzynski’s point about Exelon’s role.
Bullis said it is vital to create “well-defined roles for utilities to not only invest in infrastructure to support transportation electrification, but to do it on longer time horizons and to do it at a much larger scale. If we want a resilient grid, then let’s make sure we’re deploying assets or chargers that really fit the use case for the expected dwell time. Let’s have smart chargers so we can better manage the load.”
Keynote speakers for the webinar were Illinois Gov. J.B. Pritzker, supporting the crucial role of state governments in the initiative, and Gabe Klein, executive director of the U.S. Joint Office of Energy and Transportation.
The NRDC assisted in planning the event and provided speakers.
The California Energy Commission awarded grants totaling more than $46 million on Wednesday to four manufacturers of electric tractors, forklifts, car batteries, and charging stations with the intent to bolster in-state production of zero-emission vehicles and equipment.
Ranging from about $8 million to more than $14 million, the grants are among the largest manufacturing subsidies ever awarded by the CEC, part of a $184.7 million funding opportunity announced in March.
“We’re decarbonizing agriculture. We’re decarbonizing passenger vehicles. We’re decarbonizing industry, and we’re doing that by building things here,” CEC Chair David Hochschild said before the unanimous vote. “That is checking so many boxes, it’s just really exciting to me.”
The state is a leading manufacturer and exporter of ZEVs and related products. With Energy Commission oversight, the state and private industry are developing one of the world’s largest lithium sources in an area of Southern California known as Lithium Valley. (See ‘Lithium Valley’ Could Accelerate Calif. EV Sector Growth.)
“This is Lithium Valley,” Hochschild said of the manufacturers and products that received the grants. “These are all part of the same ecosystem. We’d like to see these electric vehicles being served with California lithium ultimately.”
More than 400 jobs will flow from the incentives, all of which were matched by industry, the CEC said.
The grants included $13 million to Monarch Tractor to establish a production line for its MK-V Electric Tractor and attachments in Livermore, California. The grant will help the state achieve its goal of reducing emissions from agriculture, its largest industry, by building 720 to 1,440 battery electric tractors per year, the CEC said.
A $10 million-plus grant to American Lithium Energy Corp., of Carlsbad, will help construct a fully automated battery cell assembly line that is expected to produce 1.5 million electric vehicle batteries annually while increasing the use of U.S. lithium and other domestic supplies, it said.
Wiggins Lift Co. of Oxnard received an $8.1 million grant to modernize and expand its Oxnard plant to increase production of its “eBull” zero-emission forklifts.
The largest grant of $14.6 million went to ChargePoint to increase its output of Level 2 charging stations and direct-current fast charging dispensers to 10,000 units each by 2026, the CEC said. The company manufactures its products in two facilities in the San Francisco Bay Area.
The increase in chargers will eventually reduce carbon dioxide emissions by up to 1.6 million metric tons and create 264 manufacturing jobs, the commission said.
“A lot of people don’t know that right now California is the No. 1 source of ZEV manufacturing jobs, and we want to keep it that way,” said Commissioner Patty Monahan, who leads the CEC’s clean transportation efforts. That can be difficult because of California’s higher costs, so “these grants, I think, are welcome to the industry,” she said.
New York’s John F. Kennedy International Airport is planning an 11.34-MW microgrid powered by solar and fuel cells to cut emissions and continue operations during power outages.
The plan is part of the replacement of three international terminals at JFK with New Terminal One — a 2.4-million-square-foot facility with a $9.5 billion price tag.
It includes rooftop solar panels with 7.66 MW of generating capacity; fuel cells with 3.68 MW capacity; and batteries rated at 2 MW/4 MWH.
The microgrid will be configured in four separate systems that will be connected to the power grid but also able to function independently and to power the airport if needed. The project will use re-claimed heat to generate chilled water and heating hot water and is expected to result in a 38% reduction in greenhouse gas emissions.
AlphaStruxure on Thursday announced the agreement to design, build and operate the microgrid. The Boston-based company is a joint venture of investment firm Carlyle and energy infrastructure firm Schneider Electric.
No price tag was announced for the microgrid, which will operate under an energy-as-a-service contract.
Construction of New Terminal One began in September. The first gates are expected to open in 2026, and completion is targeted for 2030.
The more than 13,000 rooftop solar panels will be the most at any U.S. airport and will make JFK the first transit hub in the New York City region that can function off-grid during power interruptions.
Many military airfields have microgrids, and a growing number of civilian airports are adding such capacity. Pittsburgh International Airport in 2021 said it became the first airport in the world to be fully powered by an on-site microgrid.
As at JFK, the Pittsburgh microgrid was built, paid for and operated by an outside company — Peoples Gas. A notable difference is that the 20-MW system relies on five generators burning natural gas from on-site wells to supplement its roughly 10,000 solar panels.
The zero-emissions microgrid at JFK will mesh with the decarbonization goals of the Port Authority of New York and New Jersey, which operates the airport.
New Terminal One CEO Gerrard Bushell said “sustainability and resilience” are central to the airport’s overhaul.
“This is future-focused infrastructure that will facilitate the transition away from fossil fuels and sets a new standard for large-scale renewable development in New York and in the air transit sector,” he said. The partnership with AlphaStruxure also provides New Terminal One with price certainty, insulating the terminal from volatile energy markets, he added.
NYISO CEO Rich Dewey has rebuked NextEra Energy Transmission New York (NYSE:NEE) for attempting to “lobby” the grid operator to award it transmission projects to connect offshore wind projects to Long Island.
“The NYISO cannot, under its applicable rules, select a project based upon political, parochial or commercial interests,” Dewey said in a Jan. 5 letter, which was first reported by POLITICO. “Grassroots lobbying efforts and media coverage are simply not part of the NYISO’s evaluation of the more efficient or cost-effective solution” to the transmission needs identified by the Public Service Commission.
In August 2021, the ISO solicited projects to add “at least one bulk transmission intertie cable to increase the export capability of the [Long Island Power Authority]-Con Edison interface, that connects NYISO’s Zone K to Zones I and J to ensure the full output from at least 3,000 MW of offshore wind is deliverable from Long Island to the rest of the state” and upgrades to associated local transmission facilities to accommodate the offshore export capability.
Of 19 proposals received from four developers, the ISO last April identified 16 “viable” projects, including nine from NEETNY’s New York Renewable Connect. LS Power, Anbaric Development Partners and the New York Power Authority/New York Transco also made the short list.
Long Island offshore wind projects under development | NextEra Energy
NEETNY’s website for the project includes seven “letters of support” from labor unions, elected officials and others.
The New York State Laborer’s Organizing Fund, for example, said “NEETNY is the only potential developer that has actively reached out to the local labor communities where these lines will be constructed to pledge their commitment to good union jobs and involved us in their process.”
The “Western New York Delegation,” which includes three state senators and two assemblymen, praised the company for its “extraordinary level of communication and capability” in building the 20-mile Empire State Line, the first competitively bid transmission project in the state.
None of the other competitors’ project websites included such testimonials.
In an email to RTO Insider, Kevin Lanahan, NYISO’s vice president of external affairs and corporate communications, said “the independence of the NYISO is paramount.”
“This process, as with much of our work, requires that decisions are made according to an impartial analysis of facts and data, as stipulated in our tariff,” and furthermore “the outcome is critical to the climate goals of the state and reliability of the power grid,” which is why “when attempts to introduce outside influence into the decision-making process became apparent, we determined the prudent course of action was to remind all participants of the criteria being considered,” Lanahan said.
After initially declining to comment, NEETNY told RTO Insider late Wednesday that it would comply with the ISO’s rules.
“As with any project, we always reach out early to the local community and key stakeholders to explain the project need, gather feedback and establish an ongoing dialogue so that if our proposal is selected for construction, we can quickly begin engaging with local partners to incorporate their input,” NEETNY President Richard Allen said in a statement.
“NextEra Energy Transmission New York is grateful to be a participant in the New York Independent System Operator’s Public Policy Transmission Needs process, and we are committed to continue following the processes they have set forth.”
NYISO’s Management Committee on Wednesday approved the ISO’s proposed tariff revisions related to the expiration and transfer of capacity resource interconnection service (CRIS).
The multiyear effort intends to enhance CRIS rules, with the objective of spending 2023 finishing the functional software requirements necessary to allow the ISO to track partial CRIS expirations.
The proposals seek to facilitate increased capacity deliverability by lowering the cost of new entry into the capacity market for an internal generator or an unforced capacity deliverability rights (UDR) facility looking to either transfer their CRIS rights to a same-location unit or expire their partial CRIS rights.
NYISO also adjusted the CRIS retention rules by enabling deactivated facilities to simply notify the ISO at any point that they will voluntarily relinquish their CRIS.
The Long Island Power Authority continued to object to the changes, saying they “do not address their concerns with CRIS expirations associated with interregional transmission ties with UDR,” while three other organizations abstained from the vote. (See ‘CRIS Revisions Advance,’ NYISO Business Issues Committee Briefs: Jan. 18, 2023.)
The proposals now move to the Board of Directors for approval. NYISO anticipates filing the rules with FERC before the end of the first quarter.
External and Virtual Transaction Errors
Sheri Prevratil, NYISO counterparty and credit risk manager, told stakeholders that the ISO identified typographical errors in the tariff language related to changes to credit requirements for external and virtual transactions, approved last year. (See ‘Credit Requirements on Virtual Transactions,’ NYISO Management Committee Briefs: Nov. 30, 2022.)
Prevratil said the two errors “changed one digit in the import supply table and one digit in the virtual supply table,” though these “did not affect the analysis presented to the MC, and [the ISO has] already updated the presentation and tariff language” accordingly.
In response to a question from Howard Fromer, who represents Bayonne Energy Center, Prevratil confirmed that the tariff changes have not yet been filed with FERC and said NYISO intends to first seek board approval for them in February.
As Californians ponder how the state can achieve a 100% clean energy future while maintaining electric reliability, the chair of the California Energy Commission this week offered a two-part solution.
“Offshore wind coupled with storage is how we do that,” CEC Chair David Hochschild said. “Those two things to me go hand-in-hand.”
Hochschild’s comments came Monday during an offshore wind webinar hosted by the California Natural Resources Agency. One listener asked Hochschild if there’s a guarantee that the state will stop using “the dirtiest forms of energy” once offshore wind is deployed.
Hochschild noted that state law requires all electric retail sales to come from renewable and zero-carbon resources by 2045. At the same time, he said, “the paramount issue is reliability.”
The CEC chair spoke enthusiastically about offshore wind, which he said could power a home for a day with a single turbine rotation.
“In my judgment, after rooftop solar, offshore wind is the lowest-impact form of electric generation in the world,” Hochschild said. And offshore wind is “highly aligned” with the late afternoon and early evening hours when power is most needed, he said.
The webinar was moderated by Natural Resources Secretary Wade Crowfoot as part of his Secretary Speaker Series. Crowfoot said more than 500 people tuned in to the session.
Optimizing Locations
For California offshore wind, floating turbines would be 20 to 30 miles off the coast — a location with potential environmental advantages.
“We are very pleased … that this floating technology is able to push projects 20-plus miles from shore,” said webinar speaker Kristen Hislop with the Santa Barbara-based Environmental Defense Center. “Many environmental groups are very concerned about projects closer to shore.”
Hislop said the nonprofit is optimistic about offshore wind’s potential to help California fight climate change, reduce air pollution and improve energy reliability. At the same time, she said, choosing offshore wind sites should consider species and habitat data and not just wind speed and technical considerations.
“We don’t want to see projects inadvertently impact migrating whales, birds and bats, sea turtles, sharks, fishes and other animals that rely on the California coast,” Hislop said.
Another webinar speaker was state Sen. John Laird (D), whose Central Coast district includes the site of the Diablo Canyon nuclear power plant.
Laird said he took part in negotiations over postponing the retirement of Diablo Canyon’s two reactors, which had been planned for 2024 and 2025. The state is now eyeing a 2030 closure date for the plant.
“I helped fashion that deal in a way that if there was going to be an extension, it would be just extended to the time that offshore wind was coming on, so that we could transition the transmission in that area to use [for] the offshore wind,” Laird said.
First Auction Completed
Last month, the U.S. Bureau of Ocean Energy Management held an offshore wind auction for five leases off the Northern and Central California coasts. The auction, the first for the West Coast, brought in $757 million from the five winning bidders combined. (See First West Coast Offshore Wind Auction Fetches $757M.)
The five lease areas — three off the Central Coast in the Morro Bay Wind Energy Area and two off the Northern California coast in the Humboldt Wind Energy Area — have a total capacity of up to 4.6 GW.
That’s far short of the state’s goal of 25 GW of offshore wind capacity by 2045, and some are already thinking about the next auction.
“We need to move quickly to develop siting plans for the next set of call areas,” said Adam Stern, executive director of Offshore Wind California, an industry coalition.
Stern pointed to planning areas off the coast of Mendocino and Del Norte counties, saying there’s potential for another auction within two years. He said stakeholder involvement is crucial.
“It’s critical that all of the constituencies that are represented on this call are part of this discussion,” Stern said.
That theme was emphasized throughout the webinar.
“How do we get this done as quickly as climate change demands?” Crowfoot said in recapping the offshore wind conversation. “But in a way that’s actually inclusive and thoughtful and careful to avoid and mitigate impacts.”
